The production of heavy oil and bitumen from subsurface reservoirs, such as oil sands or shale oil, is challenging. One of the main reasons for the difficulty is the viscosity of the heavy oil or bitumen in the reservoir. At reservoir temperature the initial viscosity of the oil is such that it is difficult to produce if not mobilized using external heat. As a result, the removal of oil from the reservoir is typically achieved by introducing sufficient energy into the reservoir, such that the viscosity of the oil is reduced sufficiently to facilitate oil production.
An in situ extraction known as Steam-Assisted Gravity Drainage (SAGD) may be used for extracting oil sand or shale oil deposits. The heavy oil is immobile at reservoir temperatures, and therefore, the oil is typically heated to reduce its viscosity and mobilize the oil flow. In SAGD, pairs of injector and producer wellbores are formed to be laterally extending in the ground, where an injector is positioned in the injector wellbore and a producer is positioned in the producer wellbore.
As illustrated in FIG. 1, the injector 10 is used to typically inject steam 12, and the producer 20 collects the heated crude oil or bitumen 22 that flows out of the formation 30, along with any water from the condensation of the injected steam. The injected steam 12 forms a steam chamber 14 that expands vertically and horizontally in the formation 30. The heat from the steam 12 reduces the viscosity of the heavy crude oil or bitumen 22, which allows it to flow down into the producer 20 where it is collected and recovered. The steam rises due to its low density. Oil and water flow is by gravity driven drainage urged into the producer 20.
A problem may arise in maintaining thermal efficiency of the steam 12 throughout the length of the injector 10, and into the steam chamber 14 that expands vertically and horizontally in the subterranean formation 30. Typically, the steam 12 condenses at the far end of the injector 10. Dry steam may be available up hole and wet steam down hole, such that steam enthalpy diminishes with well length. This means that the oil sand or shale oil deposits at the far, down hole end of the injector 10 may not be extracted.
To address this problem, non-condensable gases may be co-injected with the steam. For example, U.S. Published Patent Application No. 2012/0247760 discloses co-injecting steam with non-condensable gases such as CO2, flue or combustion gases, and light hydrocarbons. The non-condensable gases provide an insulating layer at the top of the steam chamber, resulting in higher thermal efficiency.
Another approach to maintain thermal efficiency of the steam throughout the injector, and into the steam chamber, is to co-inject microwave energy absorbing substances with the steam, as disclosed in U.S. Published Patent Application No. 2010/0294490. As the steam and microwave energy absorbing substances expand throughout the steam chamber, radio frequency (RF) energy is used to target the microwave energy absorbing substances. The RF energy interacts with the microwave energy absorbing substances through a coupling phenomenon. The microwave energy absorbing substances are exposed to an alternating electric field which causes the microwave energy absorbing substances to rotate or reorient in order to follow the electromagnetic (EM) field of the RF energy source, and thereby couple with, or absorb, the RF energy. Sustained reorienting of neighboring molecules, as well as different orientations of dipole moments due to changing of the EM field, generate heat.
Even in view of the above approaches, there is still a need to improve the efficiency or quality of the steam throughout the length of the injector, and into the steam chamber that expands in the subterranean formation.